Thursday, March 11, 2021

Number Of Years Of Drilling Left In The Bakken -- Rystad -- March 11, 2021

See this post.

WTI Closes Above $66; Adds 2.45% -- Only One New Permit; Fifteen Permits Renewed; Global Warming To Smack Denver -- March 11, 2021

More global warming:

The winter storm also has the potential to be among the biggest ever to hit Denver.  

The current snowfall record there is 45.7 inches in December 1913, followed by 31.8 inches in March 2003. Numerous other storms there have dropped around 2 feet of snow. 

For this upcoming storm, in Wyoming, the NWS is forecasting total snow accumulations of up to 32 inches in and around cities like Cheyenne, noting that wind gusts of 45 mph and "blizzard conditions" are possible. 

Time to re-think all those windmills?

Dow, S&P 500 hit new records.

Active rigs:

Active Rigs1556655945

One new permit, #38208 -

  • Operator: Petro-Hunt
  • Field: West Ambrose
  • Comments: Petro-Hunt has a permit for a Gubranson well 
    • in West Ambrose, lot 2 section 1-163-100;
    • the well will be sited 275 FNL 2325 FEL

Fifteen permits renewed:

  • BR (5): five George permits, all in McKenzie County;
  • Kraken (5): three Cass permits and two King permits, all in Williams County
  • Liberty Resources Management (3): one Orris permit and one Dolores permit, both in Burke County; one Esther permit in Mountrail County;
  • XTO (2): two Frisinger permits in Williams County;

Two producing wells (DUCs) reported as completed:

  • 36239, drl/A, Slawson, Moray Federal 5-10TFH, Big Bend, first production, --; t--; cum --;
  • 37255, drl/A, EOG, Liberty LR 116-1416H, Parshall, first production, --; t--; cum --;

Another Reader Weighs In On The Ever-Changing US Shale Revolution -- March 11, 2021

A reader posted a long discussion in response to an earlier post. Prior to receiving those comments, I received a note from another reader via e-mail. The e-mail from that reader is posted below with slight editing.

OilPrice article and my comments here.

From the reader regarding my comments on the article:

I was so glad to see you refer to that Oilprice article and [comment on] many of the important components stated and/or implied by that author's belated grasp of what has been occurring in this Shale Revolution.

Focusing specifically upon the expanding Tier 1 acreage, there is an evolving 'commercial' aspect (for want of a better characterization) that is taking place in lock step with ever improving technological processes by which more hydrocarbons are being extracted at lower cost. 
In the Bakken, this 'commercial' aspect may best be displayed by Kraken Oil  & Gas.

Backed by private equity, Kraken has picked up acreage fairly cheaply of what might have been considered lower quality rock. 
Using these new drilling/completion techniques, plucky, privately owned Kraken can make quick decisions, take chances on cutting edge innovations, not need to answer to public investors, and operate with considerably lower overhead than larger, publicly owned peers.

I am seeing this unfold in the Appalachia Basin at lightening speed, and - as the current rig employment in the Permian now shows - the Texas E&Ps are likewise being increasingly influenced by the 'little guys'. 

Furthermore, as shown by the massive exiting of large-yet-ineffective operators,  huge amounts of productive acreage is being marketed at dirt cheap prices.

In the Appalachian Basin, this has been/is being displayed by Shell, Exxon, EOG, Chevron, Anadarko, Noble, Alta literally dumping millions of acres on the market. 
Much of this is being snapped up by little guys like Inflection, Rockdale, Olympus and several other No Names that are being formed even as we 'speak'. 
These 'little guys' are focusing on smaller, somewhat out of the way land that outfits like Continental, Hess, EQT, Range, et al do not have keen interest in (in their respective regions) as they do not economically fit into the bigger companies' strategic plans.

Olympus is a good example as they have consolidated a fairly contiguous land position northeast of Pittsburgh (enabling efficient development) and just drilled the longest Marcellus lateral on record (over 20,000 feet).

This stuff keeps evolving at blinding speed but the expansion of productive acreage continues to grow - as you have stated - NOT decrease.

Compare January, 2020, Data WIth January 2021, Data; Note: Rig Count -- Rigs Don't Matter -- March 11, 2021

Rigs don't matter (don't take that out of context):

  • One year ago, there were 55 active rigs, production: 1.4 million bopd
  • One year later, a total of 12 active rigs, production: 1.1 million bopd.

In case you missed that, let's repeat it:

  • one year ago: 55 active rigs (really, really expensive to run 55 rigs)
  • one year later: 12 active rigs (not so expensive to run just 12 rigs; and not only that, CWC have come down over the past year;

Active rigs:

Active Rigs1556655945

One has to ask: why run 55 rigs when 12 rigs seem to get about the same amount of production? Asking for a friend.

Comparing a year ago, January, 2020, data, with this year's, January, 2021 data.

January, 2020: production data posted.

  • Month-over-month crude oil production drops 3.2%.
  • rig count: 55
  • January, 2020, preliminary: 1,429,515 bopd 

This year, January, 2021 data, linked here;

  • Month-over-month crude oil production drops 3.7%.
  • 12 rigs
  • crude oil production: 1,147,374 (preliminary) 

Again, this is not like 55 rigs vs 50 rigs or even 45 rigs. This is 55 rigs vs 12 rigs. Just saying. And this has been going on for a year. Drilling came to a stop last March, 2020.

Yes, this will eventually catch up with us, but the operators are managing their assets very, very well. 

Disclaimer: I am inappropriately exuberant about the Bakken. And rational person would say this can't go on forever. But CLR, is going to systematically drill out 70 wells in the Long Creek Unit with two rigs over three years. 

By the way, this is how one makes the case for free cash flow (FCF): run 12 rigs instead of 55 and manage to get about the same amount of production.

Director's Cut -- January, 2021, Data -- Crude Oil Production Drops Almost 4% Month-Over-Month


Later, 10:49 p.m. Central Time: from twitter --

Later, 7:08 p.m. Central Time: production was down almost 4% month-over-month (happened last year, also);

  • not due to lack of rigs
  • due to high winds preventing / delaying fracking; 
  • link here;

High winds led to power outages in parts of the Bakken in January, causing oil production to fall, the state’s top regulator said Thursday upon releasing North Dakota’s latest oil figures. The state's daily crude output for January was 1.147 million barrels, a 4% drop from December. Oil data reported to the state lags by several months. [In fact, preliminary figures lag by less than six weeks. January's data -- through January 31 -- was published March 11, which means the state had the data less than six weeks after the end of the month, hardly "several months."]
“We had a day of 90 mph winds in the oil patch, so electric power was lost through significant portions of oil and gas fields,” State Mineral Resources Director Lynn Helms said. 
“It took about 10 days to fully restore the power.” The outages knocked about 50,000 barrels per day offline during that time, he said. 
North Dakota Pipeline Authority Director Justin Kringstad said February could be “another tough month.” Western North Dakota faced bitterly cold temperatures for a number of days, as well as blackouts caused by extreme cold in the southern United States.

Original Post

Director's Cut: posted, link here. The Director's Cuts are tracked here.

The usual disclaimer applies: in a long note like this, done quickly, there will be content and typographical errors. If this is important to you, go to the source.  

January, 2021, data. This is all preliminary data for January, 2021. When the final number is tallied (next month), it will reveal a slight increase in production month-over-month):

Crude price (ND light sweet):

  • today: $56.25
  • February,2021: $49.13
  • January, 2021: $41.77
  • December, 2020: $37.70
  • November, 2020: 33.22

Crude oil production:

  • January, 2021: 1,147,374 (preliminary)
  • December: 1,192,145 (preliminary); 1,191,429 bopd (final)
  • November: 1,224,540 (preliminary); 1,227,138 bopd (final)
  • October: 1,222,871 bopd (preliminary); 1,231,048 bopd (final)
  • delta:  -44,055 bopd (this is interesting -- Lynn Helms said 50K bopd were lost due to high winds in January, 2021)
  • delta:  -3.7%

Natural gas production:

  • January, 2021: 2,847,719 MCF (preliminary)
  • December: 2,892,908 (preliminary); 2,888,626 MCF / day (final)
  • November: 2,887,402 (preliminary); 2,890,376 MCF/day (final)
  • October: 2,873,654 MCF/day (preliminary); 2,881,717 (final)
  • delta: -6,8172 boepd
  • delta: -1.44%

Natural gas capture:

  • January, 2021: 94%
  • December, 94%
  • November, 93%
  • October, 93%

Rig count:

  • today: 15 (no SWD or CS rigs)
  • February, 2021: 15 (but may include CS and SWD)
  • January: 12 (but may include CS and SWD)
  • December: 14 (but may include CS and SWD)
  • October: 14 (ditto)


  • February:
    • permitted: 72
    • completed: 32 (preliminary)
  • January:
    • permitted: 49
    • completed: 59 (revised)
    • inactive: 2,597
    • DUCs: 661
    • total off line for operational reasons: 3,258
    • producing: 15,798
  • December:
    • permitted: 66
    • completed: 44 (final)
    • inactive: 2,687
    • DUCs: 668
    • total off line for operational reasons: 3,355
    • producing: 15,798 (preliminary)
  • November: 
    • permitted: 52
    • completed: 44 (preliminary
    • inactive: 2,870
    • DUCs: 710
    • total off line for operational reasons: 3,580 
    • producing: 15,601 (preliminary)
  • October:
    • permitted: 74
    • completed: 59 (preliminary); 74 (revised)
    • inactive: 2,934
    • DUCs: 724
    • total off line for operational reasons: 3,658
    • producing: 15,512 (preliminary); 15,524 (final)

Inactive Wells and DUCs
Tracked Here

Wells, permitted:

  • February, 2021: 72
  • January, 2021: 49
  • December: 66
  • November: 52
  • October: 74
  • September: 51

Wells, completed:

  • February: 32 (preliminary)
  • January, 2021: 59 (revised)
  • December: 44 (final)
  • November: 44 (preliminary); 74 (final)
  • October: 59 (preliminary); 74 (revised)
  • September: 76 (revised); 54 (final)
  • August: 66 (final)

Wells, inactive:

  • January, 2021: 2,597
  • December: 2,687
  • November: 2,870
  • October: 2,934
  • September: 3,749

Wells, waiting on completion (DUCs):

  • January, 2021: 661
  • December: 668
  • November: 710
  • October: 724
  • September: 793

Wells, producing

  • January, 2021: 15,798 preliminary;
  • December: 15,798 (preliminary); 15,800 (final)
  • November: 15,601 (preliminary); 15,620 (revised)
  • October: 15,512 (preliminary); 15,524 (revised)
  • September: 15,389
Fracking: the number of well completions has been very volatile since March (2020) as the number of active completion crews decreased from 25 to 1; then 7 with the CARES incentive (last month) and now 6 with most recent report.

A Reader Presents His/Her View Of The Bakken -- Reply To Earlier OilPrice Article And My Comments -- March 11, 2021

A reader posted a long discussion via several comments. I have posted all those comments, but to make easier and searchable those comments have been re-posted here. 

OilPrice article and my comments here

I do not agree with all of what the reader has to say, but that's fine. Over time we will see how this all plays out. 

Hopefully, in the formatting, I did not accidentally change anything. If I did, we can sort that out later. 


March 14, 2021: not discussed by the reader --

  • EURs
    • during the boom, 2007 - 2010
    • currently, 2021
  • the halo effect
  • operators managing their assets
  • multiple sub-formations in the Bakken

March 14, 2021: flashback, rigs count -- but not so much.

Later, 11:28 p.m. CT: see comment below from another reader regarding the original post.

Original Post

The Reader's Comments

Nice article and nice discussion. Some comments. Please, don't take as critical, just how nukes engage with content. [My skipper told me about being part of a group doing an inspection for an admiral on the BG carrier. The airedales and SWO-daddies came back to the big meeting with a bunch of praise. The nuke was like: dirt here, fire extinguisher out of date, since the PM folder was on the bulkhead I looked at it and they are way behind, etc. This is just how we are trained to engage.]

1. Rigs do "matter". They are just non-linear. It's like your F-15. If you go from 50% power to 100% power, you don't get twice as fast. But you do get faster. So yes, throttle "matters". It's just not linear. Caveat: I know more about how the Sturgeon responds to throttle than the Eagle. So if I get an analogy wrong, my bad. But 50% Rx power to 100% Rx power gives you less than 2X (classified) speed. Hydro/aerodynamics are nonlinear.

a. High grading: As rigs are cut, they tend to leave the more marginal sites. Thus the remaining rigs are drilling better rock. This is "in general". Of course, the individual rigs can vary based on contract length and individual operator decisions and the like. But still, industry wide, when there are less rigs, you will see them concentrated in better areas.

This was obvious in the Bakken, in 2015-2016 and in 2020, with the rigs collapsing into the center of the play. You don't see any in Divide county now, right? Being in better rock, gives more oil production released per rig. But it's not really that rigs tend to MOVE into better rock. What happens is the rigs that were in good rock remain. And the rigs in bad rocks get cut. So there is STILL A DROP from losing rigs. Just less of a drop than if you cut rigs at random.

It's like firing the bottom 50% performing salespeople. Yes, revenue will drop. But not by 50%. This is also known as the Pareto (80-20) principle.

There is also an effect of the remaining rigs tending to concentrate the better crews, better equipment, etc. (Or when adding rigs/people of getting worse equipment/newbies.) But the geology is the main form of high grading.

Of course, the opposite effect occurs when we add rigs. You get “low grading”. If I double the rigs, I'm adding a lot of rigs into worse acreage. And yes acreage matters. Divide County ain't the Sanish. So, yes equilibrium production goes up when I add rigs, but less than linearly.

Base Decline

b. Base decline: Oil wells produce more early in life and less later in life. In general. Sure, you can have individual outliers or refracks or the like. But in general, industry-wide, you have to keep putting in new wells to overcome losses from decline. If you have zero drilling (well really completions, but eventually you need to drill to complete), you will get a decline called base decline.

This is a classic issue in oil and gas production. And if anything shale wells are higher decline than conventional wells. So no, this hasn’t stopped mattering either. Of course, this isn’t the end of the world that the peak oilers want to make it out to be. But you do have to have some baseline drilling to overcome losses. Right now, overall US production is about 11 MM bopd. I estimate, we need about 450 oil-directed rigs, along with maybe 100 gas directed rigs, to maintain 11 MM bopd. This will also stabilize natural gas production. (There is a little bit of oil from “gas rigs” and even more gas from “oil rigs”.) Right now we are at about 300 oil rigs and 100 gas rigs. So we do need to add some oil rigs.

Note that base decline, itself, is not static. New wells decline very quickly (maybe 40% in first year). Older wells, decline very slowly, only a few percent a year (but are at low levels already and a small fraction of overall production). Stripper wells barely decline at all.

What this means is that the higher fraction of production coming from new wells, the larger the overall base decline is. Conversely, if you have mostly old wells, you decline slower. So, for example, California needs less rigs per bopd to overcome base decline (mostly very old wells with low decline) as compared to New Mexico (with very large fraction of production coming from recent wells. ND is in between, but more like NM than CA.

Note that base decline for a region (or the US overall) will change based on how much recent decline/growth you’ve had. So, for instance, in DEC14, base decline for the US was close to 3MM bopd/year. (Rystad estimate—and I trust them.) But by DEC16, this had dropped almost in half. What this meant then was that much less rigs were needed just to “hold serve” in DEC16 as in DEC14. Conversely of course as we grew in 17, 18, and 19, more and more of the production was extremely recent. So that rigs to overcome base decline increased. This is the Red Queen. Nothing wrong with her. She does exist. But she shows more power when you are growing fast. And actually gets less demanding after a period of shrinkage.

Note that it’s not just the level of production (e.g. 10 MM bopd versus 12 MM bopd) that affects the base decline, but the FRACTION of recent production. So, ~9.5 MM bopd in mid 2015 was a whole different kettle of fish than ~9.5 MM bopd in mid 2017. This is because the 2017 production had much less ‘new wells” as a fraction of total production. What this also meant is that it was actually EASIER to explode in late 17 and 18, than it had been in 2014-2015. Conversely, there was a bit of an air brake in 2019 and growth was not as strong (even if rigs had stayed constant--they didn’t but drop was light).

Level vs rigs (base decline)
Time Lag

c. Level versus rigs (base decline): Even if you have a fixed fraction of new/old production, level matters. Thus, if you had the exact same distribution of new/old but doubled the level, you’d need double the rigs. An easy thought experiment is if you added a second USA next to the existing USA. Well, it would need as many rigs to maintain production as the original US, so the total rig count would be double.

Of course that is just a thought experiment. But we can consider a long term US producing 15 MM bopd versus 10 MM bopd. And if we assume same percent old/new, then we’d need 50% more rigs.

In reality, this effect tends to be smaller than the percent old/new, especially when oil prices gyrate and production grows/shrinks significantly. It does occur of course. But it is less significant than the “percent new” issue. At least for shale. At least recently. Nevertheless, despite being less significant, it is routinely confused with the percent new issue. Perhaps because it is just easier mentally to think about. (As it is easier to think of linear effects than nonlinear ones…this after all is a linear effect, remember our duplicate USA thought experiment.)

d. Time lag: Adding rigs does not instantly change production. It takes time. So if you have speed X at 50% throttle, you don’t instantly go to speed Y at 70% throttle. There is a process called acceleration. Acceleration changes instantly with your throttle. You can feel it even. But air speed takes time. Of course, eventually, you will end up at whatever is the equilibrium speed (where thrust equals air resistance). But you don’t get there instantly. This seems crushingly obvious when driving, flying, or the like. But you still see people routinely confuse this in discussions of oil production. It just takes time, to get to the new equilibrium. You can’t judge things off of one week or month or the like. Even leaving aside all the other confounders like DUCs.  


e. Equilibrium level versus increase/decrease in rigs: An increase in rigs only leads to an increase of production if you are above the level needed for base decline. Let’s say you need 450 rigs to maintain production. If we are at 300, we might add 50 rigs, but still decline. This doesn’t mean rigs are useless. It just means you need to be higher than 450 (or whatever the number is). It’s just like flying. If you are going 600 knots at throttle X, and you go to zero, you will start slowing down. Now, if you move the throttle to less than 0.5 X, you might still keep slowing down. You won’t slow down as fast. But you will keep slowing down. This doesn’t mean throttle is useless. I routinely see peak oilers (and shale boosters) messing this concept up.

f. DUCS: DUCs are a curious thing. At equilibrium, you will have some percent of DUCs at any time, given the delay between drilling and fracking. This varies from play to play and project to project, but a typical delay might be about 5 months or so for modern shale wells. Thus if rigs drop, there is still an inventory of wells that can be completed.

Drilling is about one third of the cost. Fracking is about two thirds. What this means is as prices drop, the justification for drilling a new well (spending for drilling and completion) will fall faster than the justification for completion. Remember CLR a few years ago saying “we’ll drill new wells at $60, but we’ll complete DUCs at $50”. Thus as price drops, production will fall a bit slower than expected from rig count. Because there is this inventory of completeable wells.

This is a temporary phenomenon of course. Eventually the completable excess DUC inventory gets cleaned out. (There are some “rotten DUCs” of course. Also some new DUCs from remnant drilling, but I’m talking about the inventory of excess DUCs that will get done at the new price, but wouldn’t be drilled now.)

This can be confounded by issues with contracting length (more rigs are on annual contracts, whereas completion tends to be more ad hoc purchased). But IN GENERAL, the impact of DUC inventory is to slow decline. You still reach the SAME new lower quasiequilibrium (for a lower rig count), but it just takes longer.

Note, of course, that the opposite effect can occur during a boom. If I double the rigs, it takes five months or so, to start seeing the benefits. This can be even longer if pumping equipment goes into short supply, during a boom. Again, this doesn’t change the new higher quasiequilibrium LEVEL. Just to time to get there.


g. “Technology”: Over time the industry gets better. Shale is still a relatively new phenomenon. We find ways to do things cheaper. We try new methods (some work, some don’t, but the ones that work eventually win out). In some cases, there’s just a “practice” effect of getting better at doing the tasks, especially for younger workers.

Note this is not an instant effect. The best way to think of it is as a slow grind of improvement. Not as discovering new drugs or superconductors. But it really is happening and is important.

I would argue that the pace has definitely dropped, compared to 2010-2016. But it’s still happening and helpful. A noteworthy, relatively late, example is the Haynesville renaissance. Even the recent Bakken increases are notable (both being “older plays”…maybe in some ways benefiting from learning from the younger plays.) But don’t oversell it either. I mean we haven’t had a Barnett/Fayetteville renaissance have we?

Note also, that when you see EIA’s DPR double during a price crash, that does NOT mean technology doubled. The time frame for tech is much slower. What you are seeing in a few months is high grading, not technology.

Also, of course, when rigs get added fast, out of a crash and DPR drops, we didn’t suddenly get shitty at technology. Yeah, there are some “green hats” and worse equipment coming into the plays…but the big impact is geological low grading. That is what you are seeing.

h. “Inventory”. Oil is a non-renewable resource. As a play is drilled out, inventory of drillable locations drops. Now, yes, we do find new areas with time. The EF came in later than the Bakken. And the Permian came in late (and the Delaware within that). And the Utica (gas/cond play, not the oil we hoped for) came in late. And even within plays we learn things. But arguably new information has been relatively slow since 2013 or so. And we have/are drilling out some of the best land. There’s a reason why EOG is concentrating more in the Permian and less in the Bakken and EF. They had GREAT land in EF/Bakken. But…they drilled it. That does happen. It’s not the end of the day. I actually think if you just take “technology” and “inventory” and cancel them against each other, it’s close to right. But you can’t just ignore it. Can’t say it doesn’t occur. That there are zero head winds.

Note also that, “child wells” are not as good as “parent wells”. It’s not some peak oiler end of the world catastrophe. But it’s also not some cheerleader irrelevant factor either. And that it doesn’t really matter that much if you drill them at the same time or over time. If you increase the density, the per well production drops (regardless of timing). Now, it can still be useful…sort of like adding rigs themselves. But there’s a headwind. CLR had great slides explaining the concept. Every added well helps the overall production, but drops the per well production. Since the wells cost money, you end up with an optimization problem (like a maximum in freshman calculus). But basically child wells are not as good. You can actually think of child wells as Tier 2 hiding inside the Tier 1.

Also, yes, with technology (broadly defined to include cost savings), we can sort of consider Tier 2 to move to Tier 1. But we already took CREDIT for technology. So, to just completely ignore depletion doesn’t make sense.

I prefer my simple-minded rough technology and depletion counteract idea. It pushes back on both the overenthusiastic cheerleaders and the overgloomy peakers. Check out Trisha Curtis of Petronerds, she has similar idea, I think. Realistically what this means is good for the cornucopians. But don’t be over-cornie. Depletion is not completely non-existent.  

Rigs Vs Frack Crews

i. Rigs versus frack crews: In the SHORT term what matters is fracking crews since they really lead to oil. But in the LONG term, every completed well needs to have been drilled. So if you care about the long term impact of production for ND and the US (and I think you do), then rigs matter. Once you work through excess DUC inventory, you need rigs. You just do. It’s math. It’s physics. The sea is a harsh mistress.

So, if you are looking at the long term issues of oil independence, watch rigs. Frack crews will come up/down, eventually. But every DUC needs to be drilled. If you want to know where production is headed to long term, look at rigs, not frack crews.

There is also an issue of data quality. Rig count has very high quality, granularity. Rig count is very poorly tracked and has a lot of modeling inside the numbers. Granted, this can be like looking for the keys under the lamppost. But I think you can understand the appeal of a metric that has high quality, low lag versus another with a lot of uncertainty/modeling. Well, I hope you can.

2. The Price Study
3. Transport

2. The Price study is pretty old in the tooth now.
More recent studies have been like in the 200s B bop. I know you like the cornucopian things. And I’m even broadly on your side. But be a critical thinker please. I trust the more recent assessments more. Don’t just believe in the things were you like the answer. Be a thinking observer.

Note also that oil in place is pretty different than recoverable oil. Maybe 50 years from now, we recover it all (or 50% of it). But given current techs and reasonable medium term extrapolations, you need to take a huge haircut on oil in place versus recovered oil. This still leaves you a lot of oil. And if you take USGS at about 10 BBO and just double it (from being old, etc.) to 20 BBO, it’s still a metric shit ton (submariner unit of measure). But it ain’t 450 BBO either.

And it ain’t the Permian. It just isn’t. I know you want it to be. But it ain’t. Try to be a critical thinker versus a cheerleader. USGS is putting the Permian at 70+ BBO. And that is recoverable. Not “in place”. Oh…and the Persian Gulf has even more. You need to be apples to apples. Don’t compare oil in place (Bakken) to recoverable (Permian). It’s just not intellectually honest.

3. Transport: The Bakken is a great play. But you can’t teleport it to TX. You can’t teleport the CA oil sands either. It costs money to move stuff. And the Bakken faces a headwind on transport. It just does.

And don’t you dare say DAPL doesn’t matter. If that gets shut down…it will be a cost impact. And even the possibility that that happens is making people slow down on adding rigs, and yes, they fu…ricking matter (sorry, attack boats are all male and live in the 50s). If DAPL was assured and Keystone were approved 100%, you’d have 80 rigs running. You really would. And they matter.

US Shale -- Folks Are Starting To Get It -- March 11, 2021

Someone finally gets it. Link here. Rig counts don't matter. How long have I been saying this? Finally, someone gets it. This will be re-posted as a stand-alone post. Perhaps the only thing that needs to be read this week. Maybe this month. Stay tuned. I will post the link later. Don't worry I won't forget. It's a great article. The writer made only one mistake of any real substance. Archived.

Mr Messler begins:

I have written on shale production in the U.S. a number of times over the past couple of years for OilPrice.

My expectation that shale production would fall sharply to ~5-6 mm BOEPD by the end of 2020, has not been borne out.

My view was that a lack of drilling/completion activity due to adverse price conditions would cause production to fall sharply.

Historical annual decline rates for shale wells can be as high as 60% in the first year. [Another meme.]

In this article I discuss some of the reasons I feel this has occurred and what it may portend for oil supplies and prices going forward.

Actual production though has stayed at levels I didn't think would be possible last year. I am on record as having thought U.S. shale production would finish 2020 between 5-6 mm BOEPD.

As of the most recent EIA Drilling Productivity Report, U.S. shale production from the seven major plays has remained in a range of 7.6-7.5 mm BOEPD. [And production would be much higher if prices justified greater production.]

Why was author wrong earlier on?

  • technology: drilling / completion -- extracting more oil per unit of interval than even just a few years ago
  • operator high grading of their portfolios to focus almost solely on Tier 1 acreage

And then get this: rigs don't matter

Finally, production is somewhat delinked currently from the rig count, which still is less than half what it was before the pandemic. Operators have been choosing to bring Drilled but Uncompleted Wells-DUCs, online to maintain a flat to slightly rising production level, as opposed to mobilizing a lot of rigs to make new wells. In December, for example 159 DUCs were withdrawn from inventory as noted in last month's EIA-Drilling Productivity Report.

Again, the writer must be talking mostly about the Permian.

Active rigs in the Bakken are well below "less than half what they were before the pandemic." The NDIC says the Bakken has about 15 active rigs; Baker Hughes puts the number even lower by one or two. And, yet, production has pretty much plateaued; production certainly hasn't "followed' rig count.

I do take issue with the comment about DUCs. I've seen it anecdotally, and another reader has provided monthly data to suggest, that overall, in the oil basins, DUCs have not decreased much. 

In fact, the DUCs that do get reported in the Bakken have come to the end of their regulatory deadline and must be completed or plugged and abandoned. Operators in the Bakken don't seem to be completing DUCs to maintain production; DUCs being reported as completed are almost entirely at the regularly deadline and must be completed. And even then, anyone following this closely, note all the wells that are "said to have come off the DUC list, and yet they are not reporting any production; most have not even been completed. 

The "operators relying on DUCs to maintain production" has become a meme that is not true in the Bakken. I think that's also true in the Permian but I don't follow it closely enough to say with confidence. 

The author addresses the Tier 1 concern:

One of the questions that often comes up is what will happen when Tier I acreage is drilled up. Some estimates have been put forward that this might occur within the next decade. 
Rystad has challenged those estimates showing an estimate of the longevity of Tier I shale in years at present rates of drilling. 
It comes as no surprise the Delaware sub-basin of the larger Permian basin is the king of shale, and operators there will retain a low cost drilling advantage for a number years beyond other plays.

Folks may want to go back and review the original Leigh Price study. 

In addition, "Tier 1" is not static. Not only has the Tier 1 footprint grown significantly in the last few years, Tier 1 acreage is "getting better." 

If one wants to be amazed, or let's say "woke" in this case, see the Rystad graph at the link. The initial Rystad estimate was made in 2019; the current Rystad estimate was made in 2020. 

With regard to Tier 1:

Of interest also is a recent report that challenges some of the assumptions about lower tier acreage being substantially less valuable than Tier I
In a 2019 article carried in the Journal of Petroleum Technology, a Deloitte study was showcased that showed some geological shortcomings could be overcome by application of technology of the type we have discussed in this article. 
Further it challenged the assumption that rock quality alone was the determinant in obtaining maximum production from a well. We won’t develop that concept further in this article, except to note that it plays into the larger thesis that American shale production will be a vibrant contributor to the nation’s energy security for decades to come.

Wow, wow, wow -- that's been another consistent theme on the blog: the assumption that rock quality alone was the determinate in obtaining maximum production from a well. We would begin with the microseismic array but then we would have to do some real research.

Again, one may want to re-read the original Leigh Price article. 

The Market: A Most Remarkable Day -- To Say The Least -- March 11, 2021


Later, 10:43 a.m. CT

Original Post

An interesting number keeps popping up: 34%. For example, analysts see a 34% upside for QCOM. There's a reason for this particular number. 

We can look at any number of stocks, but since we were talking about QCOM, let's stay with that.

Kroger To Close Three Underperforming Stores
After Los Angeles Mandated Hazardous Pay

Link here. This is an old story, previously published. 

Kroger said Wednesday, March 10, 2021, it will close three stores in Los Angeles after local officials approved mandated $5-per-hour hazard pay for grocery and drug store workers during the COVID-19 crisis.

The Cincinnati-based grocer will shutter two Ralphs and one Food 4 Less stores in the city on May 15, 2021. It will continue to operate 65 other stores in the city. The retailer heaped criticism on local officials for dumping millions of additional expenses on it in the middle of the pandemic.

"It becomes impossible to operate these three stores," Kroger said in a statement, noting the mandate will cost nearly $20 million over the next 120 days. It noted local employees already averaged hourly pay of $18, $24 when considering benefits.

Taking A Break -- The Literature Page -- March 11, 2021

First this:

Why? In the current issue of The New York Review of Books, page 15, "Splash," by Marina Warner, an essay / book review of Merpeople: A Human History, Vaughn Scribner, Reaktioin, 318 pp, $27.50. 

Sophia loves unicorns and mermaids. And here we have a long, long -- 2.5 pages -- essay on mermaids, or as Scribner calls them, merpeople. This is not simply politically correct, or "woke," but sea-people can be both men and women. Even Sophia knows that. 

Marina (what an apt first name for an essay on marine people, LOL), begins:

In 1819 the French inventor Cagniard de La Tour gave the name sirène to the alarm he had devised to help evacuate factories and mines in case of accident—in those days all too frequent. The siren, or mermaid, came to his mind as a portent, a signal of danger, although it might seem a contradiction, since the sirens’ song was fatal to mortals: in the famous scene in the Odyssey, Odysseus ties himself to the ship’s mast to hear it, and orders his men to plug their ears with wax and ignore him when he pleads to be set free to join the singers on the shore. Homer does not describe these irresistible singers’ appearance—only their flowery meadow, which is strewn with the rotting corpses of their victims—but he tells us that their song promises omniscience: “We know whatever happens anywhere on earth.” This prescience inspired Cagniard: he inverted the sirens’ connection to fatality to name a device that gives forewarning.

In Greek iconography, the sirens are bird-bodied, and aren’t instantly seductive in appearance but rather, according to the historian Vaughn Scribner in Merpeople, “hideous beasts.” A famous fifth-century-BCE pot in the British Museum shows Odysseus standing stiffly lashed to the mast, head tilted skyward, his crew plying the oars while these bird-women perch around them, as if stalking their prey: one of them is dive-bombing the ship like a sea eagle. An imposing pair of nearly life-size standing terracotta figures from the fourth century BCE, in the collection of the Getty Museum, have birds’ bodies and tails, legs and claws, and women’s faces; they too have been identified as sirens (see illustration below).

So, "siren," as an "alarm," was a word coined by a French inventor. 

From the internet:

The Music Page

From the same issue of The New York Review of Books, p. 31, "This Ain't No Disco," Dan Chiasson, an essay / book review on Remain in Love: Talking Heads, Tom Tom Club, Tina, Chris Frantz, St Martin's, 384 pp, $29.99.

Chris Frantz was the drummer for the Talking Heads and the Tom Tom Club.

Some time ago I posted a note about Tina Weymouth on the blog, a most fascinating woman, and then, lo and behold, someone else thought the same thing, wrote a book, and then someone else writes an essay on all of that. Amazing. 

By the way, on a completely different note, "Chiasson" is a lovely surname, isn't it?

The four members of the American band Talking Heads came from intact, midcentury American families, with kind and presentable parents who turned up at their gigs, or supplied a hand-me-down station wagon for touring, or fluffed the guestroom pillows when the band came through town. 
Chris Frantz, the drummer, was a prep school kid from Kentucky and Pittsburgh whose first memories included Christmas parties at Harvard Law School, where his father, a West Point graduate who later became an army general, was a student; later, Frantz played in the woods at Monticello, where his mother volunteered. 
When Frantz got to know his wife, Tina Weymouth, the band’s bassist, she was living in her parents’ carriage house on a leafy street in Providence, Rhode Island. Weymouth’s father, Ralph Weymouth, was an admiral who became a prominent antinuclear activist; her mother was from an old French family, and together they raised eight children. 
David Byrne’s Scottish parents, an engineer and special education teacher, had settled outside of Baltimore in a house they decorated with their son’s art projects. 
Jerry Harrison, the only child of an ad executive and a painter, came on board late, in 1977. Harrison, a veteran of the Boston band Modern Lovers, was working toward an architecture degree when Frantz, Weymouth, and Byrne turned up at his drafting desk at the Harvard School of Design and persuaded him to join the band.

The "names" that keep crossing paths here, 1973 - 1979, or who stole from whom, or who influenced whom, or who learned from whom:

  • The Talking Heads
  • The Tom Tom Club
  • CBGB
  • Suzi Quatro
  • Blondie

Over-posted but no option, just the links for now:

And Finally, Because Everything Must Be Done In "Threes"

"Awful But Joyful," Deborah Eisenberg, pp. 43, an essay / book review of two books:
The Copenhagen Trilogy: Childhood; Youth; Dependency, Tove Ditlevsen, 370 pp., $30.00; and,
The Faces, Tove Ditlevsen, 129 pp., £8.99 (paperback)

The essay begins:

By the time Tove Ditlevsen committed suicide in 1976, she was one of Denmark’s most popular and acclaimed writers. In the fifty-eight years of her life, she’d had two children and custody of a third, and four husbands. She’d soared out of poverty, and all told, she’d published about thirty books—primarily collections of poetry but also novels, memoirs, stories, and children’s books. She’d written magazine pieces, too, and, of all things, an advice column.

The information readily available about her in English is oddly sketchy, and little of her work has been translated into English, but what we have includes her memoir, The Copenhagen Trilogy, and a novel, The Faces. Both were published in Danish between 1967 and 1971, though neither was translated into English until years later.

The Copenhagen Trilogy and The Faces are very different books, but they draw on the same material—Ditlevsen’s life—and both display a distinctive style; an uncanny vividness; a gift for conveying atmospheres and mental sensations and personalities with remarkable dispatch; the originality and deadpan, trapdoor humor of the significantly estranged; a startling frankness; and a terrible commotion of unresolved conflicts and torments. Both books also accelerate from zero to sixty before anyone has a chance to buckle up.

The Faces starts right off with the protagonist, Lise Mundus, experiencing flickerings of delusion, which in short order explode into full-blown psychosis. It’s generally a poor idea to go rooting around in a work of fiction for clues to its author’s life and psyche, but the invitation here is so unequivocal it seems boorish to turn it down. Among other parallels Mundus is, like the author, a famous writer, and like the author she is suffering from marital problems as well as the inability to work that’s known rather emptily as “writer’s block”; Mundus was the maiden name of Ditlevsen’s mother (who once urged her daughter to use it as a nom de plume); and Ditlevsen herself endured several institutionalizations.

My closest friend in graduate school wanted to go into psychiatry, but for various reasons ended up in research on transplantation, at the Mayo Clinic, Rochester, MN. He often said that there was a very, very fine line between madness and insanity, and of all the medical specialties, one could have the greatest impact if one could bring madness back across the line.

Here We Go -- Gasoline Demand -- March 11, 2021

Link here

Only a handful of states have announced a lifting of restrictions.

Keep that in mind when looking at this chart. 

And, US driving season has not yet begun. 

And, US consumers who drive POVs, are pivoting toward gas guzzling SUVs, cross-overs, and pickup trucks. 

And ... 

Meanwhile, the natural gas fill rate, link here

I don't know anything about natural gas. I've said that many times on the blog. But one thing I have learned. Crude oil and natural gas are very, very different entities. There will always be enough natural gas to meet demand within a fairly narrow band. 

Absolutely not true when it comes to crude oil.

Warren Buffett -- Idle Thoughts -- March 11, 2021

New headlines:

Previously posted:



  • BNSF? Best buy ever? How Berkshire Hathaway makes money, Investopedia
  • BNSF Railway Berkshire's freight rail transportation business operates one of the largest systems in North America. BNSF Railway ships coal as well as consumer, industrial, and agricultural products.
  • BNSF Railway's revenue fell 11.3% in 2020 to $20.9 billion as EBT fell 6.3% to $6.8 billion. Rail transport comprised only 9% of Berkshire's total revenue, but it generated over 25% of total EBT.

Something to think about:

  • in the big scheme of things, BNSF and Union Pacific are two peas in a pod, as they say
  • Berkshire Hathaway's EBITDA for the three months ended in December, 2020, was $49,364 million; its EBITDA for the trailing twelve months (TTM) ended in December, 2020, was $70,372 million
    • 25% of $70 billion is $17.5 billion
  • Union Pacific EBITDA for the quarter ending December 31, 2020 was $2.563B, a 3.61% decline year-over-year. Union Pacific EBITDA for the twelve months ending December 31, 2020, was $10.044B, a 6.74% decline year-over-year.

No Wells Coming Off Confidential List Today; We're Goin' To The Moon; Why US Shale Production Keeps Exceeding Expectations -- March 11, 2021

Most interesting bit of trivia posted this week: BNSF accounts for twenty-five percent of Berkshire Hathaway's EBITDA. Previously posted. I don't know about you but I find that absolutely incredible. BNSF only accounts for 9% of BRK's holdings, but accounts for 25% of its income EBITDA or something like that. I might have that wrong, but if you want to check, it was posted yesterday with a link.

We're goin' to the moon.

Firster things firster: this is so cool. Yesterday I posted a note about John Fogerty and CCR. Today, RBN Energy's choice of songs: Centerfield by John Fogerty. Whoo-hoo. Link here. I was going to post this song last night but I felt I had posted it so many times, I thought, "not again." But here we go:

By the way: from a reader, a comment from yesterday --

Regarding John Fogerty. Saw an interview with him by Dan Rather in which he was asked “how many times have you played Proud Mary?” After thinking about, Fogerty responded “not enough”.

First things first:

I've been watching sports talk television in the morning (0700 - 1200) almost exclusively for the past six months. 
It's been mostly about Dak Prescott and the Cowboys. It's amazing how "they've" missed the big story. How Jerry Jones played the media was priceless. He took lessons from Elon Musk. It's interesting that someone like me who understands the business of sports finally figured it out. For now, all I will say: Jerry Jones was brilliant. One wonders if Dak was playing along.

Don't fight the ECB. So, why are Dow futures surging after a record-setting day yesterday? Here and here.

Jobless numbers: if anyone cared, there would be more of an uproar of the loss of jobs connected with killing the Keystone XL. That's why the jobless report no longer matters. In fact, did it ever matter? Even the unions no longer care.

This seems like a problem. Link here. But then, it's been a problem for many years. 

LA ports. The Port of Long Beach posts busiest February on record amid ongoing import rush. Link here.

  • TEUs: increased over 43%, year/year -- repeat, a 43% increase year-over-year
  • loaded inbound containers grew by over 50% year over year
  • did anyone say we're going to come out of the pandemic faster than anyone expected?
  • note: although activity typically slows in February as East Asian factories close for up to two weeks to celebrate the Lunar New Year, China largely worked through the holiday to fill back orders and meet the increasing demands of consumers ordering items online;

Sad. Not sad. Every hotel was sold out in Midland last night. Link here.

Someone finally gets it. Rig counts don't matter. How long have I been saying this? Finally, someone gets it. This will be re-posted as a stand-alone post. Perhaps the only thing that needs to be read this week. Maybe this month. Stay tuned. I will post the link later. Don't worry I won't forget. It's a great article. The writer made only one mistake of any real substance. Archived.

And finally: Sonic allows customers to tip carhops with updated app at 1,000 locations. One of those locations is located across the street from our apartment complex. I go to Sonic once every five years. From a reader:

I can take or leave the rest of their menu.  They feature "Tot-chos", which are nachos made with tater tots instead of corn chips.  I know people who are absolutely addicted to them.  Tater tots have never been my thing, but they have a very loyal following.

The fresh limeade, however, calls my name every couple weeks during the summer and occasionally the rest of the year.  I order a very large drink and am always surprised that I finish the entire thing.  They're running a special now,and drinks are half price if you order them online.  They also do cherry limeade if someone likes a sweeter beverage, but I like mine tart enough to rattle my teeth just a little.

So, I don't order the largest size, I order the penultimate. LOL.
Rigs: in the Bakken -- at 12 - 15 for the past year or so. Prediction: by the end of CY21, there is a 90% chance there will be 21 active rigs in the Bakken, and a 50% chance that there will be 30 or more. I generally don't make predictions but when I do, they are usually wrong. 

Seeing the cup as half empty: me, I see the cup as half full, but Noah obviously doesn't. From Reuters, this opening from Noah:
Crude oil in storage at major land and sea hubs rose last week as a build-up in China and the US Gulf Coast reflected oil markets' bumpy road to recovery. This has nothing to do with a "bumpy road" to recovery. 
This is just how things are. Not only is the recovery not "bumpy," it's moving along a lot faster than anyone predicted six months ago. Previously posted.

Back to the Bakken

Active rigs:

Active Rigs1556655945

No wells coming off confidential list today.

RBN Energy: hydrogen slides "on deck" and ready to play. Archived.

In the world of public equities, nothing speaks relevance like a PowerPoint slide in the earnings call and conference decks that companies put together for analysts and investors. If a topic’s not important, then it probably didn’t “make the deck” — or even the appendix, for that matter. As consultants, we at RBN are familiar with this concept and we’ve been watching for some time to see just how long it would take hydrogen, one of our favorite recent subjects, to make its way into the slide-deck line-ups at some of the largest energy companies. Well, that time has arrived, with two energy stalwarts prominently featuring 2021’s darling subject over the last few days. However, with a new topic comes a need to put things in context. No problem, we are here to help on that. Today, we continue our series on H2 with a look at some recent hydrogen-focused slides from ExxonMobil and Enterprise Products Partners.

Two of my favorite companies: XOM and EPD -- both mentioned above. How good can it get!

Disclaimer: this is not an investment site.  Do not make any investment, financial, job, career, travel, or relationship decisions based on what you read here or think you may have read here. 

Clearing Out The In-Box -- Late Night Notes -- March 10, 2021


  • after hitting another all-time high, against significant headwinds (bond yields), futures suggest another interesting day tomorrow

Apple: sell-off is a golden buying opportunity. Benzinga.

  • outperform rating, target: $175
  • bull case price target: $225
  • with a trillion-dollar-valuaton in sight for Cupertino, the recent sell-off in share creates a golden buying opportunity



  • BNSF? Best buy ever? How Berkshire Hathaway makes money, Investopedia
  • BNSF Railway Berkshire's freight rail transportation business operates one of the largest systems in North America. BNSF Railway ships coal as well as consumer, industrial, and agricultural products.
  • BNSF Railway's revenue fell 11.3% in 2020 to $20.9 billion as EBT fell 6.3% to $6.8 billion. Rail transport comprised only 9% of Berkshire's total revenue, but it generated over 25% of total EBT.

Something to think about:

  • in the big scheme of things, BNSF and Union Pacific are two peas in a pod, as they say
  • Berkshire Hathaway's EBITDA for the three months ended in December, 2020, was $49,364 million; its EBITDA for the trailing twelve months (TTM) ended in December, 2020, was $70,372 million
    • 25% of $70 billion is $17.5 billion
  • Union Pacific EBITDA for the quarter ending December 31, 2020 was $2.563B, a 3.61% decline year-over-year. Union Pacific EBITDA for the twelve months ending December 31, 2020, was $10.044B, a 6.74% decline year-over-year.